1. Field of the Invention
The present invention relates to the field of well drilling and completion. More specifically, the present invention relates to direct measurement apparatus and methods for evaluating subsurface conditions in a wellbore.
2. Description of the Background Art
In a typical well drilling operation, conditions in the wellbore must be closely monitored and controlled to optimize the well operation and to maintain control of the well. One of the most important conditions in well drilling procedures is the bottomhole pressure of the circulating drilling fluid or "mud" used in forming or conditioning the well. The actual or effective density of the mud is an important condition that can be affected by a number of different variables related to the composition of the mud, the characteristics of the formation being penetrated by the wellbore, the dynamics of the drilling mechanism, and the procedures being implemented in the wellbore. In this latter regard, for example, the circulation of the fluid creates an effective density within the wellbore, referred to as an equivalent circulating density, that exceeds the static density of the fluid. The equivalent circulating density is caused by pressure losses in the annulus between the drilling assembly and the wellbore and is strongly dependent on the annular geometry, mud hydraulics, and flow properties of the well fluid. The maximum equivalent circulating density is always at the drill bit, and pressures of more than 100 psi above the static mud weight may occur in long, extended reach and horizontal wells.
This equivalent circulating density, which must be known in order to determine well pressures existing at different locations within the wellbore, may be calculated using hydraulics models from input well geometry, mud density, mud rheology, and flow properties, through each component of the circulating system. There are, however, often large discrepancies between the measured and calculated pressures due to uncertainties in the calculations through poor knowledge of pressure losses through certain components of the circulation system, changes in the mud density and rheology with temperature and pressure, and/or poor application of hydraulics models for different mud systems.
In many high pressure, high temperature (HPHT), deepwater, and extended reach and horizontal wells, the margin between the formation pore or collapse pressure and the formation fracture pressure often diminishes to the point that the equivalent circulating density can become critical. In extreme cases, the well may flow or cave in while the pumps used to circulate the mud are off ("pumps off"), allowing the well fluid to flow into the formation. Accurate determination of the actual static and dynamic mud pressures within the wellbore is therefore a critical design parameter for the successful drilling of these wells.
Another phenomenon affecting pressures in the wellbore results from movement of the drill string. As the drill string is lowered into the well, mud flows up the annulus between the string and the wellbore and is forced out of the flowline at the well surface. A surge pressure results from this movement, producing a higher effective mud weight that has the potential to fracture the formation. A swabbing pressure occurs when the pipe is pulled from the well, causing mud to flow down the annulus to fill the void left by the pipe. The pressure effectively reduces the mud weight and presents the potential for inducing a discharge of fluid from the formation into the wellbore. As with the equivalent circulating density measurements, the swab and surge pressures are strongly dependent on the running speed, pipe geometry, and mud rheology involved in the drilling or completion of the well. These pressures reach a maximum value around the bottom hole assembly (BHA), where the annular volume between the drilling string assembly and the surrounding wellbore is the lowest, and thus where flow through the well is the fastest.
Theoretical and experimental evidence suggests that during running pipe in and out of the wellbore, a much larger pressure differential is exerted on the formation than is experienced from static and circulating pressures during drilling, unless the pipe running speed is lowered significantly. Formation susceptibility to wellbore instability, although not problematic while drilling, may increase due to the swab and surge pressures incurred during tripping when the entire pipe string is rapidly withdrawn or reinserted in the well.
Modeling swab and surge pressure is difficult because of the manner in which the fluid flows as the pipe is moved within the well. A moving pipe causes the mud adjacent to the pipe to be dragged with it to a certain extent, although the bulk of the annular fluid is moving in the opposite direction. The mechanics are therefore different from the hydraulics calculations described for the mud circulation since, in that case, fluid flow is considered to be only moving in one direction. Swab and surge hydraulics models therefore require a "clinging constant" to account for the two relative motions.
A pressure surge caused by breaking the gels when increasing the flow rate too quickly after breaking circulation has been responsible for many packoff and lost circulation incidents. In this situation, where the well circulation is terminated for a period of time ("pumps off") and then reinitiated ("pumps on"), if the circulation rate is reinitiated too quickly, a pressure surge is created in the mud, causing a damaging imbalance with the formation. This danger, which is particularly evident in high angle wells, led to the procedure of slowly bringing the volume of the mud pumps up anytime after circulation is temporarily suspended. A pressure surge associated with restarting circulation may also be caused by a restriction in the annulus due to cuttings sagging and accumulating while the mud is static.
In extended reach and horizontal wells, hole cleaning can become critical. If parts of the wellbore are unstable, as in common in these types of wells, the accumulation of cuttings, beds, and an overloaded annulus make it difficult to clean the hole properly. Remedial measures, such as control drilling, the pumping of viscous pills, and wiper trips, are commonly employed in an attempt to avoid packing off and sticking the pipe.
These procedures, however, consume valuable time and may also damage the formation leading to further wollbore instabilities.
Yet another situation where knowledge about the subsurface conditions is important occurs when drilling out of the bottom of a casing shoe into new formation.
It is common to perform a leak-off test (LOT) to determine the strength of the cement bond around the casing shoe. However, because of the small margins between the formation pore or collapse pressure and fracture pressure in many wells, the LOT has become a critical measure of the formation strength and is used as a guide to the maximum allowable circulating pressure that may be used in a subsequent hole section without breaking down the formation and losing circulation in the well.
Conventionally, LOT pressures are recorded at the surface of the well. The measurements must be corrected for the pressure being exerted by the mud column. To obtain an accurate reading in these surface conducted measurement procedures, the mud must be circulated thoroughly to condition it to produce an exact and even density for the LOT calculation. This process can be time-consuming, and the calculated results are subject to the correctness of the information and assumptions used for the values of the variable conditions affecting the mud column density.
Subsurface pressure information is especially important when the well "takes a kick" during drilling. The term "kick" is commonly employed to describe the introduction of formation gas, a lower density formation fluid, or a pressured formation fluid into the wellbore. If not controlled, the kick can reduce the density of the drilling fluid sufficiently to allow the formation pressure to flow uncontrollably through the well and become a "blowout." In riserless offshore drilling, the kick can allow formation fluids to flow into the sea.
After the kick is detected and the well is shut in, the stabilized casing shut-in pressure and the stabilized drill pipe shut-in pressure are measured at the well surface and recorded. The drill pipe shut-in pressure is used as a guide in determining the formation properties. Since the formation fluid type is generally unknown, it is not possible to determine the formation pressure from the casing shut-in pressure. The formation pressure and influx volume are required to calculate the density of the mud required to "kill" the well. While circulating the kill mud, the annular pressure is controlled by the choke and pump speed to maintain a constant bottom hole formation pressure and prevent further entry of formation fluid. As with the other evaluations dependent upon fluid or mud pressure, the accuracy of the calculations is dependent upon the correct evaluation of the factors affecting the mud density.
Another situation that requires knowledge of the mud column density is that of determining the mud weight. The mud weight is normally determined at the well surface from surface mud checks or sensors in the flowline or the return pit. It has been proposed that the mud density actually decreases with temperature increases due to expansion and that this effect may become important in HPHT wells with tight margins between the formation pressure and the webore pressures. In high angle wells, a heavy cuttings load may increase the annular mud weight significantly. Additionally, a number of measurements can be made during a trip to detect barite sag, which also affects the mud weight.
A conventional pressure while drilling (PWD) tool can be used to measure the differential well fluid pressure in the annulus between the tool and the wellbore while drilling mud is being circulated in the well. These measurements arc employed primarily to provide real-time data at the well surface, indicative of the pressure drop across the BHA for monitoring motor and measurement while drilling (MWD) performance. The measurement values are also affected by the effects of the circulating well fluid. Direct annular pressure measurements were not customarily made.
Downhole well pressures may also be measured directly using a drill-stringsupported tool isolating a section of the wellbore from the effects of the well fluid above the point of measurement. U.S. Pat. No. 5,555,945 (the '945 patent) describes a tool that employs an inflatable packer with an MWD instrument designed to sense fluid pressure or temperature, or other variable well characteristics. The measurement is typically made in the annulus between the tool and the formation in the area below the set packer. The packer is set and the subsurface variable is measured and recorded in an instrument contained within an assembly of the tool. The recorded data is retrieved to the surface by pulling the drill string and assembly from the well. Constant remote communication may be maintained with a surface command station using mud pulse telemetry or other remote communication systems.
U.S. Pat. No. 5,655,607 describes a drill-string-supported, inflatable packer that can be anchored in an open wellbore and used to measure well pressures above or below the packer. An internal cable control is used to regulate inflation and deflation of the packer. Subsurface measurement data are presumably sent directly through the cable to the well surface or recorded and retrieved when the assembly is retrieved to the well surface.
In some MWD systems, downhole temperature and pressure, as well as other parameters, are measured directly, and the measured data values are communicated to the surface as the measurements are being made using "fluid pulse telemetry" (FPT), also called "mud pulse telemetry" (MPT). FPT, such as described in U.S. Pat. No. 4,535,429, requires that the well fluid be circulated to transmit data to the well surface. While data transmission during circulation of the well provides information on a timely basis, the measurements taken are affected by the fluid circulation and must be corrected for its effects. This requirement imposes the same uncertainties previously noted regarding calculated values for subsurface parameters, computer modeling, and surface measurement techniques used to estimate a subsurface condition.
It is also possible to directly obtain subsurface measured data using transmission techniques that do not rely on circulating well fluid. For example, subsurface measurement and transmitting devices using low frequency electromagnetic waves transmitted through the earth to a receiver at the surface are capable of transmitting data without regard to whether the well fluid is circulating or static. These devices, however, are not suitable for use in all applications and also require highly specialized transmitting and receiving systems that are not as commonly available as are the FPT systems.
MWD systems that use MPT are only able to send information to the surface while circulating. Thus, real-time pressure and temperature information can only be sent real time while circulating the mud system. However, much information useful to well drilling and formation evaluation processes can be gained from the data recorded while the pumps are off. While the pumps are off, pressure and temperature and other data are recorded at a specific sampling rate. On resumption of circulation, this stored information is transmitted to the surface using FPT. This may be as detailed as each discrete recorded sample. However, sending all data may take an unacceptable amount of time. Some smart processing downhole will reduce the amount of data that has to be sent up.
U.S. Pat. No. 4,216,536 (the '536 patent) describes a system that, among other things, uses the storage capacity in a subsurface assembly to store data measurements of a downhole condition made while the drilling liquid is not circulating. The stored data is transmitted to the well surface after flow of the drilling liquid is resumed using FPT. Subsurface temperature and formation electrical resistivity are examples of the conditions sensed and recorded while the circulation of the drilling fluid is interrupted. The '536 patent also discloses a method for increasing the effective transmission rate of data through FPT by deriving and transmitting condensed data values for the measured conditions. The '536 patent employs multiple transducers on a logging tool for measuring a number of downhole conditions.
U.S. Pat. No. 5,353,637 (the '637 patent), describes multiple, axially spaced inflatable packers included as part of a wireline or coil tubing supported sonde that is used to conduct measurements in cased or uncased boreholes. The '637 patent system measures conditions in the wellbore between axially spaced inflatable packers and sends the measurement values to the surface over the supporting wireline cable.
The '945 patent, previously noted, describes methods and apparatus for early evaluation testing of subsurface formation. A drill-string-supported assembly that includes one or more well packers and measuring instruments is used to measure subsurface pressures. Recorded measurements are accessed by retrieval of the drill string or connection with a wireline coupling. The system may also provide constant remote communication with the surface through mud pulse telemetry.